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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q/A NO. 1
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File No. 0-25058
OCEAN ENERGY, INC.
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 72-1277752
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
1201 LOUISIANA, SUITE 1400
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code: (713) 420-1000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
The number of shares outstanding of the registrant's common stock, all of which
comprise a single class with a $0.01 par value, as of November 10, 1998, the
latest practicable date, was 101,167,184.
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OCEAN ENERGY, INC.
FORM 10-Q/A NO. 1
SEPTEMBER 30, 1998
This Amendment No. 1 relates only to Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operations and provides
additional information regarding the Company's Year 2000 compliance efforts.
TABLE OF CONTENTS
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PAGE
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PART I - FINANCIAL INFORMATION
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........ 3
SIGNATURES ............................................................................................ 10
</TABLE>
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
On December 23, 1997, the Company announced that it entered into a
Merger Agreement with UMC that provided in part for a stock-for-stock merger of
UMC with and into the Company. Pursuant to the Merger Agreement, at the
effective time of the Merger, the Company's stockholders received 2.34 shares
of the combined company's common stock for each share of the Company's common
stock then owned and UMC stockholders received 1.30 shares of the combined
company's common stock for each share of UMC stock then owned. The Merger,
effective March 27, 1998, was treated as a pooling of interests for accounting
purposes.
This financial review summarizes the combined financial condition and
results of operations giving retroactive effect to the Merger and should be
read in conjunction with the Company's supplemental consolidated financial
statements and the notes thereto included in the Form 8-K filed May 6, 1998.
The consolidated financial statements previously filed in the Company's Form
10-K for the year ended December 31, 1997, have been restated therein to
reflect the combination of the historical results of OEI and UMC and conforming
of accounting policies in accordance with the pooling of interests method of
accounting.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the Company for
the periods shown:
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- --------------------------
1998 1997 1998 1997
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
PRODUCTION:
Oil (MBO)
U.S. . . . . . . . . . . . . . . . . . . . 3,399 3,192 11,034 8,512
Canada . . . . . . . . . . . . . . . . . . 121 110 339 322
Cote d'Ivoire . . . . . . . . . . . . . . 321 250 714 818
Equatorial Guinea . . . . . . . . . . . . 1,669 1,191 4,557 2,870
--------- --------- --------- ---------
Total . . . . . . . . . . . . . . . . . 5,510 4,743 16,644 12,522
========= ========= ========= =========
Natural gas (MMCF)
U.S. . . . . . . . . . . . . . . . . . . . 24,639 20,788 74,525 57,960
Canada . . . . . . . . . . . . . . . . . . 2,289 1,940 7,018 5,410
Cote d'Ivoire . . . . . . . . . . . . . . 1,910 1,452 5,525 3,612
--------- --------- --------- ---------
Total . . . . . . . . . . . . . . . . . 28,838 24,180 87,068 66,982
========= ========= ========= =========
AVERAGE WELLHEAD SALES PRICE, INCLUDING HEDGING:
Oil ($ per bbl)
U.S. . . . . . . . . . . . . . . . . . . . $ 13.85 $ 18.11 $ 14.48 $ 19.22
Canada . . . . . . . . . . . . . . . . . . $ 12.08 $ 16.78 $ 12.05 $ 18.16
Cote d'Ivoire . . . . . . . . . . . . . . $ 11.52 $ 18.41 $ 13.33 $ 18.55
Equatorial Guinea . . . . . . . . . . . . $ 11.70 $ 17.78 $ 12.38 $ 17.97
Average . . . . . . . . . . . . . . . . $ 13.02 $ 18.01 $ 13.81 $ 18.86
Natural Gas ($ per MCF)
U.S. . . . . . . . . . . . . . . . . . . . $ 1.85 $ 2.18 $ 2.00 $ 2.28
Canada . . . . . . . . . . . . . . . . . . $ 1.23 $ 1.20 $ 1.27 $ 1.39
Cote d'Ivoire . . . . . . . . . . . . . . $ 1.64 $ 1.76 $ 1.67 $ 1.80
Average . . . . . . . . . . . . . . . . $ 1.79 $ 2.07 $ 1.92 $ 2.18
ADDITIONAL DATA ($ PER BOE):
Production and operating costs (1) . . . . . $ 3.72 $ 2.81 $ 3.26 $ 3.05
General and administrative expense . . . . . $ 1.05 $ 0.77 $ 1.00 $ 0.86
Oil and natural gas depletion and depreciation $ 6.70 $ 7.65 $ 6.89 $ 7.22
</TABLE>
_____________
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(1) Costs incurred to operate and maintain wells and related equipment,
excluding ad valorem and production taxes of $0.53 and $0.55 per BOE for the
three months ended September 30, 1998 and 1997, and $.52 and $0.65 per BOE for
the nine months ended September 30, 1998 and 1997, respectively.
NINE MONTHS ENDED SEPTEMBER 30, 1998 COMPARED WITH NINE MONTHS ENDED SEPTEMBER
30, 1997
Operating revenues. The Company's total operating revenues increased
$14.7 million, or 4%, to $399.1 million for the nine months ended September 30,
1998, from $384.4 million for the comparable period in 1997. Production levels
for the nine months ended September 30, 1998, increased 32% to 31,155 MBOE from
23,686 for the comparable period in 1997 in spite of significant storm-related
shut-ins of production from the Gulf of Mexico during the third quarter. The
increase in oil and gas revenues is due to increased oil volumes in the Gulf of
Mexico and Equatorial Guinea and overall higher gas volumes, offset by
significant declines in oil and gas prices.
Oil revenues decreased $6.4 million, or 3%, to $229.8 million for the
nine months ended September 30, 1998, from $236.2 million for the nine months
ended September 30, 1997, the result of significantly increased worldwide
production volumes offset by a decline in the average realized price received.
Oil production increased 33% to 16,644 MBO for the first nine months of 1998 as
compared to the same period in 1997 due primarily to increased oil production
in the Gulf of Mexico and Equatorial Guinea. The average sales price before
hedging for oil decreased 32% to $12.78 in the first nine months of 1998
compared to $18.87 in the same period in 1997.
Natural gas revenues increased $21.6 million, or 15%, to $167.5 million
for the nine months ended September 30, 1998, from $145.9 million for the nine
months ended September 30, 1997, the result of increased worldwide production
which more than offset the decline in prices received for gas. Natural gas
production for the nine months of 1998 was 87,068 MMCF, an increase of 30% over
1997 volumes due primarily to increased production in the Gulf of Mexico, Cote
d'Ivoire and Canada and the impact of acquisitions, offset by property sales,
storm-related shut-ins in the Gulf of Mexico and natural production declines in
North America. The average sales price before hedging for natural gas decreased
12% to $1.92 per MCF in the first nine months of 1998 as compared to $2.18 in
the first nine months of 1997.
For the nine months ended September 30, 1998, the Company's total
revenues were further affected by a $17.8 million increase in hedging revenues.
In order to manage its exposure to price risks in the sale of its crude oil and
natural gas, the Company from time to time enters into price hedging
arrangements. The Company's average sales prices including hedging for oil and
natural gas for the nine months ended September 30, 1998 were $13.81 per Bbl
and $1.92 per Mcf compared to $18.86 per Bbl and $2.18 per Mcf in the
comparable 1997 period.
Production costs. Total production costs increased $30.2 million, or
34%, to $118.0 million for the nine months ended September 30, 1998 from $87.8
million for the comparable 1997 period. This increase primarily results from
fluctuations in normal operating expenses, including operating expenses
associated with increased production from new facilities, timing of workover
and maintenance activities, and the impact of property acquisitions.
Production and operating costs (costs incurred to operate and maintain wells
and related equipment, excluding ad valorem and production taxes) increased
$.21 per BOE, or 7%, to $3.26 per BOE for the nine months ended September 30,
1998, from $3.05 per BOE in the comparable 1997 period. This unit increase is
primarily the result of the timing of certain workover and maintenance
activities.
General and administrative expenses. General and administrative
expenses increased $10.8 million, or 53%, to $31.1 million for the nine months
ended September 30, 1998 from $20.3 million in the comparable 1997 period.
This increase is primarily due to costs of increased corporate staffing
associated with both an increase in drilling activities and the Company's
property acquisitions in 1997. In addition, costs related to a new systems
implementation, partially offset by an increase in the capitalization of a
portion of the salaries paid to employees directly engaged in the acquisition,
exploration and development of oil and gas properties in accordance with the
full cost method of accounting, contributed to the increase. As a result of
these factors, general and administrative expenses per BOE increased by $0.14
per BOE, or 16%, to $1.00 per BOE for the nine months ended September 30, 1998,
from $0.86 per BOE for the comparable 1997 period.
Depreciation, depletion and amortization expense. Depreciation,
depletion and amortization (DD&A) expense increased $43.7 million, or 25%, to
$217.7 million for the nine months ended September 30, 1998, from $174.0
million for the comparable 1997 period. This variance is primarily
attributable to the Company's increased production and
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related current and future capital costs from the 1997 and 1998 Gulf of Mexico
and international drilling programs and acquisitions, partially offset by the
effect of an increase in proved reserves resulting from such programs and
acquisitions. Oil and gas DD&A decreased $0.33 per BOE, or 5%, to $6.89 per
BOE for the nine months ended September 30, 1998, from $7.22 per BOE for the
comparable 1997 period. The non-cash write-down of oil and gas properties
recognized in the second quarter of 1998 contributed to the decrease.
Write-down of oil and gas properties. As required under the full cost
method of accounting, capitalized costs are limited to the sum of the present
value of future net revenues using current unescalated pricing discounted at
10% related to estimated production of proved reserves and the lower of cost or
estimated fair value of unevaluated properties, all net of expected income tax
effects. At June 30, 1998, the Company recognized a non-cash impairment of oil
and gas properties in the amount of $218.4 million pre-tax ($135.4 million
after-tax) pursuant to this ceiling limitation required by the full cost method
of accounting for oil and gas properties, using certain improvements in pricing
experienced after period end. The write-down is primarily a result of the
precipitous decline in world crude oil prices experienced during the second
quarter 1998.
Interest and debt expense. Reported interest and debt expense increased
$4.3 million, or 12%, to $40.6 million for the nine months ended September 30,
1998, from $36.3 million in the comparable 1997 period. This increase is
primarily the result of an increase in debt levels during the year of 1998
resulting from the capital spending program in place for 1998 and lower than
expected cash flows due to the deterioration in product pricing, offset by an
increase in capitalized interest on significant projects in process. Average
total debt outstanding for the nine months ended September 30, 1998 was $938.7
million as compared to $584.7 million for the same period in 1997.
Merger Costs. Merger costs of $39.0 million were recorded in the first
quarter of 1998. These costs consist primarily of investment banking and other
transaction fees, employee severance and relocation costs as well as the
write-off of deferred financing costs related to the former credit facilities
replaced by the OEI Credit Facility in March 1998.
Income tax provision (benefit). An income tax benefit of $88.0 million (of
which $3.3 million is a current provision and $91.3 million is a deferred
benefit) was recognized for the nine months ended September 30, 1998, compared
to a provision of $27.9 million (of which $5.0 million was a current provision
and $22.9 million was a deferred provision) for the nine months ended September
30, 1997. Current taxes include a $2.9 million non-cash provision representing
current taxes incurred in Cote d'Ivoire which, under the terms of the
production sharing contract, will be paid by the Ivorian government from their
production proceeds. The deferred tax benefit for the nine months ended
September 30, 1998 is further impacted by the non-cash write-down of oil and
gas properties and the tax treatment of certain merger costs, a portion of
which is not deductible for tax purposes. Consistent with Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, the
deferred income tax provision or benefit was derived primarily from changes in
deferred income tax assets and liabilities recorded on the balance sheet.
Extraordinary loss on early extinguishment of debt. On July 22, 1997, the
Company purchased approximately $124.8 million of the $125.0 million original
principal amount of the 13 1/2% Notes for approximately $151.5 million. This
repurchase resulted in an after-tax extraordinary charge of $19.3 million,
representing the difference between the purchase price and the net carrying
value of the 13 1/2% Notes.
Net income (loss). Due to the factors described above, the net loss for
the nine months ended September 30, 1998, was $(177.4) million, a decrease of
$198.6 million from net income of $21.2 million for the comparable 1997 period.
THREE MONTHS ENDED SEPTEMBER 30, 1998 COMPARED WITH THE THREE MONTHS ENDED
SEPTEMBER 30, 1997.
Material changes in the results of operations between the three months
ended September 30, 1998 and 1997, primarily reflect the significant increases
in oil and natural gas production volumes offset by decreases in prices
received and other activities as previously discussed. Oil and natural gas
production volumes for the third quarter 1998 were adversely affected by
storm-related shut-ins in the Gulf of Mexico during the period.
5
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LIQUIDITY AND CAPITAL RESOURCES
The following summary table reflects comparative cash flows for the Company
for the nine months ended September 30, 1998 and 1997 (in thousands):
<TABLE>
<CAPTION>
Nine months ended September 30,
-----------------------------------
1998 1997
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<S> <C> <C>
Net cash provided by operating activities $ 150,036 $ 227,003
Net cash used in investing activities (670,408) (554,304)
Net cash provided by financing activities 523,232 288,810
</TABLE>
Net cash provided by operating activities for the nine months ended
September 30, 1998, includes the impact of the non-recurring merger costs.
Capital requirements. The Company's capital investments to date have
focused primarily on exploration, acquisitions and development of proved
properties. The Company's expenditures for property acquisition, exploration
and development for the nine months ended September 30, 1998 and 1997 are as
follows:
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Nine months ended September 30,
----------------------------------
1998 1997
--------------- -------------
(in thousands)
<S> <C> <C>
Property acquisition costs:
Proved . . . . . . . . . . . . . . . . . . . . . . . $ 27,828 $ 111,366
Unproved . . . . . . . . . . . . . . . . . . . . . . 29,946 55,755
Exploration costs . . . . . . . . . . . . . . . . . . . . 272,067 154,887
Development costs . . . . . . . . . . . . . . . . . . . . 297,365 279,332
Capitalized interest on unevaluated properties . . . . . 21,990 8,094
Capitalized general and administrative costs . . . . . . 18,875 10,824
-------------- -------------
Total costs incurred . . . . . . . . . . . . . . . . . . $ 668,071 $ 620,258
============== =============
</TABLE>
The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploration, development, production and
abandonment of its oil and natural gas reserves. The Company has historically
funded its operations, acquisitions, exploration and development expenditures
from cash flows from operating activities, bank borrowings, sales of equity and
debt securities, sales of non-strategic oil and natural gas properties, sales
of partial interests in exploration concessions and project finance borrowings.
The Company intends to finance remaining 1998 capital expenditures related to
this strategy primarily with funds provided by operations, borrowings or other
capital market activities.
The Company's capital expenditure budget for 1998 is expected to be
approximately $725.0 million (excluding proved property acquisitions) focused
on the Company's three operating regions. In addition, the Company will
evaluate its level of capital spending throughout the year based upon drilling
results, commodity prices, cash flows from operations and property
acquisitions. Actual capital spending may vary from the capital expenditure
budget.
The Company's debt to total capitalization ratio increased to 68.3% at
September 30, 1998, from 48.1% at December 31, 1997. The Company's interest
coverage ratio (calculated as the ratio of income from operations plus DD&A and
impairment of proved oil and gas properties to reported interest expense plus
capitalized interest less non-cash amortization of debt issue costs) was 4.1 to
1 for the first nine months of 1998 compared with 6.5 to 1 for the first nine
months of 1997.
Concurrent with the closing of the Merger on March 27, 1998, the Company
entered into a $750.0 million five-year unsecured revolving credit facility
(OEI Credit Facility) which combined and replaced the Revolving Credit Facility
and the Global Credit Facility. The OEI Credit Facility, which is with a group
of commercial banks, provides for various borrowing options under either a base
rate or Eurodollar margin rates and provided a $600.0 million initial borrowing
base. Borrowings against the facility were repaid in July 1998 with the
proceeds from a $500.0 million Notes Offering made by the Company pursuant to
Rule 144A, which notes were subsequently exchanged for publicly-traded
instruments with identical terms. At that time, the credit facility was
amended and restated to a $400.0 million, five-year revolving credit facility
with an initial borrowing base of $300.0 million. As of September 30, 1998,
total borrowings outstanding
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against the facility were approximately $189.0 million, leaving approximately
$111.0 million of available credit. On November 10, 1998, the Company received
commitments to increase the borrowing base under the facility to $400.0
million, resulting in available credit of $211.0 million on a pro forma basis
at September 30, 1998.
On November 10, 1998, the Company completed a private placement of 50,000
shares of Series A Convertible Preferred Stock for $38.0 million of oil and gas
properties and $12.0 million in cash from one of its institutional investors.
The Series A shares have a 6.5% cumulative dividend payable semi-annually
beginning April 1, 1999.
Liquidity. The ability of the Company to satisfy its obligations and fund
planned capital expenditures will be dependent upon its future performance,
which will be subject to prevailing economic conditions, including oil and gas
prices, and subject to financial and business conditions and other factors,
many of which are beyond its control, supplemented if necessary with existing
cash balances and borrowings under the OEI Credit Facility. The Company
currently expects that its cash flow from operations and availability under the
OEI Credit Facility will be adequate to execute its 1998 business plan.
However, no assurance can be given that the Company will not experience
liquidity problems from time to time in the future or on a long-term basis. If
the Company's cash flow from operations and availability under the OEI Credit
Facility are not sufficient to satisfy its cash requirements, there can be no
assurance that additional debt or equity financing will be available to meet
its requirements.
Effects of Leverage. The Company has outstanding long-term indebtedness of
approximately $1,203.3 million as of September 30, 1998. The Company's level
of indebtedness has several important effects on its future operations,
including (i) a substantial portion of the Company's cash flow from operations
must be dedicated to the payment of interest on its indebtedness and will not
be available for other purposes, (ii) the covenants contained in the various
indentures require the Company to meet certain financial tests, and contain
other restrictions which limit the Company's ability to borrow additional funds
or to dispose of assets and may affect the Company's flexibility in planning
for, and reacting to, changes in its business, including possible acquisition
activities and (iii) the Company's ability to obtain additional financing in
the future for working capital, expenditures, acquisitions, general corporate
purposes or other purposes may be impaired. None of the indentures place
significant restrictions on a wholly-owned subsidiary's ability to make
distributions to the parent company.
The Company believes it is currently in compliance with all covenants
contained in the respective indentures.
The Company's ability to meet its debt service obligations and to reduce
its total indebtedness will be dependent upon the Company's future performance,
which will be subject to oil and gas prices, general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors.
OTHER MATTERS
Energy swap agreements. The Company hedges certain of its production
through master swap agreements (Swap Agreements) which provide for separate
contracts tied to the NYMEX light sweet crude oil and natural gas futures
contracts. In addition, the Company has combined contracts which have agreed
upon price floors and ceilings (Costless Collars). As of September 30, 1998,
the fair market value of all hedging contracts was approximately $4.0 million.
Oil and gas revenues have been increased by $6.4 million and $17.5 million
for the three and nine months ended September 30, 1998 as a result of the hedge
contracts in place for each period. As of September 30, 1998, the Company's
open forward position on its outstanding crude oil Swaps was 1,050 MBbls at an
average price of $19.87 per Bbl for the year ended December 31, 1998. The
Company currently has no outstanding natural gas swaps.
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Currently, the Company's open forward position on its outstanding natural
gas Costless Collars is as follows:
<TABLE>
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Effective Contracted Contracted Contracted
------------------ Volumes Floor Ceiling
Year From Through (MMBTU/day) Price Price
---- ---- ------- ----------- ----- -----
<S> <C> <C> <C> <C> <C>
1999 January December 30,000 $2.10 $2.550
1999 January December 20,000 $2.10 $2.605
1999 January December 40,000 $2.10 $2.630
1999 January December 10,000 $2.10 $2.650
</TABLE>
It is the Company's current intention to commit no more than 50% of its
production on a BOE basis to such arrangements at any point in time. As the
current Swap Agreements expire, the portion of the Company's oil and natural
gas production which is subject to price fluctuations will increase
substantially unless the Company enters into additional hedging transactions.
Price fluctuations and volatile nature of markets. Despite the measures
taken by the Company to attempt to control price risk, the Company remains
subject to price fluctuations for natural gas and oil sold on the spot market.
Prices received for natural gas sold on the spot market are volatile due
primarily to seasonality of demand and other factors beyond the Company's
control. Domestic oil prices generally follow worldwide oil prices which are
subject to price fluctuations resulting from changes in world supply and
demand. Any significant decline in prices for oil and gas could have a
material adverse effect on the Company's financial position, results of
operations and quantities of reserves recoverable on an economic basis.
Environmental. The Company's business is subject to certain federal,
state, and local laws and regulations relating to the exploration for, and the
development, production and transportation of, oil and natural gas, as well as
environmental and safety matters. Many of these laws and regulations have
become more stringent in recent years, often imposing greater liability on a
larger number of potentially responsible parties. Although the Company
believes it is in substantial compliance with all applicable laws and
regulations, the requirements imposed by such laws and regulations are
frequently changed and subject to interpretation, and the Company is unable to
predict the ultimate cost of compliance with these requirements or their effect
on its operations. Under certain circumstances, the MMS may require any
Company operations on federal leases to be suspended or terminated. Any such
suspensions, terminations or inability to meet applicable bonding requirements
could materially and adversely affect the Company's financial condition and
operations. Although significant expenditures may be required to comply with
governmental laws and regulations applicable to the Company, to date such
compliance has not had a material adverse effect on the earnings or competitive
position of the Company. It is possible that such regulations in the future
may add to the cost of operating offshore drilling equipment or may
significantly limit drilling activity. The Company has included approximately
$10.0 million in its 1998 exploration and development capital budget to
reformat operations for alternative disposal of water produced from its
offshore wells in accordance with an approved zero discharge plan.
The Oil Pollution Act of 1990 (OPA) imposes ongoing requirements on a
responsible party including proof of financial responsibility to cover at least
some costs in a potential spill. For tank vessels, including mobile offshore
drilling rigs, the OPA imposes on owners, operators and charterers of the
vessels, an obligation to maintain evidence of financial responsibility of up
to $10.0 million depending on gross tonnage. With respect to offshore
facilities, proof of greater levels of financial responsibility may be
applicable. This amount is subject to upward regulatory adjustment up to
$150.0 million.
Year 2000 compliance. Historically, most computer systems, including
microprocessors embedded into field equipment and other machinery, utilized
software that recognized a calendar year by its last two digits. Beginning in
the year 2000, these systems will require modification to recognize a calendar
year by four digits.
Accordingly, the Company has initiated a comprehensive plan to address the
year 2000 issues associated with its operations and business. OEI's board has
been briefed about the year 2000 problem generally and as it may affect OEI.
The board has assigned its Audit Committee to oversee the adoption and
implementation of a year 2000 plan. A committee of senior executives has been
created to develop a plan and manage its implementation. The aim of the plan
is to take reasonable steps to prevent OEI's mission-critical functions from
being impaired due to the year 2000 problem.
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The plan includes several phases - (a) assessment of all of the Company's
systems and technology; (b) implementation and testing of modifications to or
replacements of existing systems and technology, both financial and
operational; (c) communication with key business partners; and (d) contingency
planning.
In planning and developing the project, OEI has considered both its
information technology ("IT") and its non-IT systems. The term "computer
equipment and software" includes systems that are commonly thought of as IT
systems, including accounting, data processing, telephone systems, scanning
equipment, and other miscellaneous systems. Those items not considered IT
technology include alarm systems, metering devices, monitors for field
operations, and other miscellaneous systems. Both IT and non-IT systems may
contain embedded technology, which complicates OEI's year 2000 identification,
assessment, remediation, and testing efforts. Based upon its identification
and assessment efforts to date, OEI is in the process where necessary, of
reprogramming or replacing the computer equipment and software it currently
uses to become year 2000 compliant. In addition, the Company's primary
information systems are in the process of being replaced with fully compliant
new systems as part of a regularly scheduled upgrade to meet the Company's
growing capacity and performance requirements. The testing of the systems
under consideration should be completed by April 1999.
The Company is utilizing both internal and external resources to reprogram,
or replace, and test much of its IT systems, primarily financial and
operational software, for necessary modifications identified in its assessment
of year 2000 issues. As of the date of this filing, the Company estimates that
approximately 60% of its year 2000 plan for these IT systems has been
implemented and anticipates that the remainder of the plan, including any
necessary remedial action, will be completed by June 30, 1999. During July
1998, the Company began utilizing internal and external resources to evaluate
its vulnerability to year 2000 issues related to its non-IT systems, primarily
field operational systems and equipment. The Company has also initiated formal
communications with all of its key business partners to determine the extent to
which the Company is vulnerable to those third parties' potential failure to
remediate their own year 2000 issues. The evaluation of non-IT systems and
communications with key business partners is well underway, and the Company
estimates that the remainder of the year 2000 plan concerning these areas will
be completed by June 1999.
The Company is currently in the process of developing contingency plans for
both financial and operational systems. OEI's contingency plans are being
designed to minimize the disruptions or other adverse effects resulting from
year 2000 incompatibilities regarding these systems, and to facilitate the
early identification and remediation of year 2000 problems that first manifest
themselves after January 1, 2000.
The failure to correct a material year 2000 issue could result in an
interruption in, or a failure of, certain normal business activities, thereby
having a material, adverse effect on the Company's results of operations,
liquidity and financial position. The Company's remediation efforts are
expected to significantly reduce the Company's level of uncertainty about year
2000 compliance and the possibility of interruptions of normal operations.
However, there can be no guarantee that the systems of other companies, on
which the Company's systems rely, will be timely converted, or that a failure
to convert by another company, or a conversion that is incompatible with the
Company's systems, would not have a material adverse effect on the Company.
Disruptions to the oil and gas transportation networks controlled by third-
party carriers could result in reduced production volumes delivered to market.
In addition, risks association with foreign operations may increase with the
uncertainty of year 2000 compliance by foreign governments and their supporting
infrastructures.
The total costs for the year 2000 compliance review, evaluation, assessment
and remediation efforts are not expected to be in excess of $1,000,000. Of
this amount, approximately $200,000 had been incurred as of December 31, 1998.
The costs of these projects and the dates on which the Company plans to
complete modifications and replacements are based on management's best
estimates, which were derived utilizing numerous assumptions of future events
including the continued availability of certain resources, third party
modification plans and other factors. However, there can be no guarantee that
these estimates will be achieved and actual results could differ materially
from those plans.
Forward-looking statements. Certain statements in this report, including
statements of the Company's and management's expectation, intentions, plans and
beliefs, including those contained in or implied by "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the Notes to
Consolidated Financial Statements, are "forward-looking statements", within the
meaning of Section 21E of the Securities Exchange Act of 1934, that are subject
to certain events, risk and uncertainties that may be outside the Company's
control. These forward- looking statements include statements of management's
plans and objectives for the Company's future operations and statements of
future economic performance; information regarding drilling schedules, expected
or
9
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planned production or transportation capacity, future production levels of
international and domestic fields, the Company's capital budget and future
capital requirements, the Company's meeting its future capital needs, the
Company's realization of its deferred tax assets, the level of future
expenditures for environmental costs and the outcome of regulatory and
litigation matters; and the assumptions described in this report underlying
such forward-looking statements. Actual results and developments could differ
materially from those expressed in or implied by such statements due to a
number of factors, including, without limitation, those described in the
context of such forward- looking statements, fluctuations in the price of crude
oil and natural gas, the success rate of exploration efforts, timeliness of
development activities, risk incident to the drilling and completion for oil
and gas wells, future production and development costs, the political and
economic climate in which the Company conducts operations and the risk factors
described from time to time in the Company's other documents and reports filed
with the Securities and Exchange Commission.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Christopher E. Cragg Vice President and Controller January 27, 1999
- ----------------------------------------- (Chief Accounting Officer)
Christopher E. Cragg
</TABLE>
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